Oil and gas is getting bigger, deeper, faster and more efficient, with new technology chipping away at “peak oil” concerns. While hydraulic fracturing has been the most visible revolutionary advancement, other high-tech developments are keeping the ball rolling—from the next generation of ultra-deepwater drillships, subsea oil and gas infrastructure and multi-well-pad drilling to M2M networking, floating LNG facilities, new dimensions in seismic imagery and supercomputing for analog exploration.
ADVANCED SEMI-SUBMERSIBLES & 6TH GENERATION DRILLSHIPS
Rig advancements are coming online in tandem with the significantly increased momentum to drill in deeper waters as shallower reserves run out. For 2012, 49% of new offshore discoveries were in ultra-deepwater plays, while 28% were in deepwater plays. What we’re looking at now are amazing advancements in deepwater rigs, with new semi-submersibles capable of drilling to depths of 5,000 feet or deeper. Beyond that, though, new sixth generation enterprise-class drillships can go to depths of 12,000 feet! From a global perspective, there are 120 ultra-deepwater rigs in existence—and demand is on the steep rises.
Subsea processing can turn marginal fields into major producers.
Subsea production systems are wells located on the sea floor rather than the surface. Petroleum is extracted at the seafloor, and then ‘tied-back’ to an already existing production platform. The well is drilled by a moveable rig and the extracted oil and natural gas is transported by riser or undersea pipeline to a nearby production platform. Subsea systems are typically in use at depths of 7,000 feet or more. They don’t drill, they just extract and transport.
The real advantage of subsea production systems is that they allow you to use one platform—strategically placed—to service many well areas. And as the cost of offshore production rises, this could represent significant savings.
Subsea production could rival traditional offshore production in less than 15-20 years, and we’re looking at expected market growth for subsea facilities of around $27 billion in 2011 to an amazing $130 billion in 2020. Analysts expect E&P companies to invest more than $19 billion in subsea production equipment in 2013 alone–and up to $33 billion by 2017.
Subsea processing can handle everything from water removal and re-injection or disposal, to single-phase and multi-phase boosting of well fluids, sand and solid separation and gas/liquid separation and boosting to gas treatment and compression.
Subsea processing allows producers to separate the unwanted elements right on the seafloor, without using complicated and expensive flowlines to bring these elements up to the above-water processing facility to remove them and then send them back down to the seafloor to be re-injected. We’re cutting out the middle man here. The middle man in this case is the process known as “subsea boosting”.
What we’re talking about, essentially, is saving space and time (which means money) by performing processing activities on the seafloor rather than sending fluids back and forth between the seafloor and the processing facilities above water.
We are particularly interested in a new subsea rotating device that promises to enhance dual-gradient drilling (DGD). This is a system being developed by Chevron, which is hoping to deploy the system is the Gulf of Mexico later this year. What the DGD system will do is render the thousands of feet of mud that is bearing down on the wellbore … well … weightless.
And then we have subsea power grid plans, which have been making progressive leaps since 2010 towards the advancement of electric grids installed on the floor of the sea to run processing systems at the site of underwater wells. It reduces the need for so many platforms on the water surface, and makes the entire process much less complicated. The ultimate goal here is to be able to operate offshore wells remotely from land—saving countless billions.
MULTI-WELL-PAD DRILLING: OCTPUS IN THE HOUSE
One of the greatest drilling developments of the last decade is multiple well pads, which some like to refer to as “Octopus” technology.
Imagine gaining access to multiple buried wells at the same time, from a single pad site. This is what “Octopus” technology is doing, first in a canyon in northwestern Colorado in the Piceance Shale Formation and then in the Marcellus shale. It’s definitely not your traditional horizontal drilling.
Traditionally, to drill a single well, a company needs a pad or land site for each well drilled. Each of these pads covers an average of 7 acres. The Octopus allows for multiple well drilling from a single pad, which can handle between 4 and 18 wells. So, a single pad on 7 acres can now be used to drill on up to 2,000 acres of reserves. More than anything, it means that drilling will be faster, faster, faster … And less expensive in the long run once it renders it unnecessary to break down rigs and put them together again at the next drilling location. It’s simple math: 4 pads usually equals 4 wells; now 1 pad can equal between 4 and 18 wells.
Here’s how the technology works: A well pad is set up and the first well is drilled, then the rig literally “crawls” on its hydraulic tentacles to another drill location from the same pad, repeatedly. And it’s multi-directional. It takes about two hours between each well drilling. With traditional horizontal drilling methods, it takes about five days to move from pad to pad and start drilling a new well.
Last year, Devon Energy (DVN) drilled 36 wells from a single pad site using Octopus technology in the Marcellus Shale. More recently, Encana (ECA) drilled 51 wells covering 640 underground acres from a single pad site with a surface area of only 4.6 acres in Colorado. Multi-well pad drilling is also revolutionizing drilling in Bakken, and this is definitely the long-term outlook for shale. It will become the norm.
It’s also good (or at least slightly better) news for the environment because it means less drilling disturbance on the surface as we render more of the process underground.
SUPERCOMPUTING & SEISMIC DIMENSIONS EINSTEIN WOULD APPRECIATE
Oil majors are second only to the US Defense Department in terms of the use of supercomputing systems. That’s because supercomputing is the key to determining where to explore next—and to finding the sweet spots based on analog geology.
What these supercomputing systems do is analyze vast amounts of seismic imaging data collected by geologists using sound waves. What’s changed most recently is the dimension: When the oil and gas industry first caught on to seismic data collection for exploration efforts, the capabilities were limited to 2-dimensional imaging. Now we have 3-dimensional imaging that tells a much more accurate story.
But it doesn’t stop here. There is 4-dimensional imaging as well. What is the 4th dimension, you ask: Time (and Einstein’s theory of relativity). This 4thdimension unlocks a variable that allows oil and gas companies not only to determine the geological characteristics of a potential play, but also gives us a look at the how a reservoir is changing LIVE, in real time. The sound waves rumbling through a reservoir predict how its geology is changing over time.
The pioneer of geological supercomputing was MIT, whose post-World War II Whirlwind system was tasked with seismic data processing. Since then, Big Oil has caught on to the potential here and there is no finish line to this race—it’s constantly metamorphosing. What would have taken decades with supercomputing technology in the 1990s, now can be accomplished in a matter of weeks.
In this continual evolution, the important thing is how many calculations a computer can make per second and how much data it can store. The fastest computer will get a company to the next drilling hole before its competitors.
We are talking about MASSIVE amounts of data from constant signal loops from below the Earth’s surface. For example, geologists generate sound waves using explosives or other methods that dig deep into the Earth’s surface and then are sample 500 times per second. Only a supercomputer could possibly process all this complex data and make sense of it.
We’ve moved beyond geographical interpretations, such as pursuing exploration based on geological proximity, like Tullow’s Ethiopia play is on trend with its massive Kenya finds. This is child’s play. What we’re talking about is using supercomputing to tell us that standing in prolific Brazil is pretty much the same as standing in Angola; or that Ghana is analog to French Guiana.
Supercomputing advances remove a great deal of the risk involved in undertaking expensive drilling when you’re not sure what’s there. Supercomputing essentially puts the idea of peak oil to bed for the foreseeable future.
LNG TECHNOLOGY: FLOATING IS NOT A FANTASY
Liquefied natural gas (LNG) technology—from LNG seaborne tankers and LNG trains to floating LNG facilities have quickly gone from concept to commercialization, opening up new possibilities in new frontiers and rendering the remote—well, much less remote.
Liquefaction of natural gas is the process of super-cooling natural gas to minus 260 degrees Fahrenheit (minus 162 degrees Celsius) at which point it becomes much safer and easier to transport. After shipped to its destination, regasification plants at importing or receiving terminals return the fuel to a gaseous state.
Floating LNG production, storage and offloading concepts are revolutionary because they have the ability to station a vessel directly over distant fields, removing the need for offshore pipelines and adding the advantage of mobility—these floating facilities can be moved to a new location once existing fields are depleted.
Floating liquefaction technology can bring additional LNG supply by accessing stranded gas reserves that were previously thought to be too remote, small or otherwise challenging for conventional land-based LNG development.
Shell’s most prized LNG project is its Prelude Floating Liquefied Natural Gas (FLNG) Project in Australia, which is moored some 200 kilometers out to sea and will produce gas from offshore fields and liquefy it onboard. This vessel will be six times bigger than the biggest aircraft carrier and will cost between $10.8 and $12.6 billion to build—but it also means that Shell won’t have to pay rising prices in Australia’s onshore LNG plants. The facility will produce about 3.6 million metric tons of LNG and 1.3 million tons of gas condensate a year.
M2M FOR OIL & GAS: GETTING SMARTER AND MORE CONNECTED
The hottest arena in the smart grid world is machine-to-machine (M2M) technology—an industry worth $1 trillion. It’s relevance to the oil and gas industry should not be underestimated. Now it’s about to get even bigger because the cost of sensors used to make M2M possible has fallen so much that they are BEYOND commercially viable; and wireless networks are now cheap and everywhere. This is the next frontier in cross-sector technology.
M2M device use in the oil and gas industry is set to more than double, as these technologies (including SCADA Telemetry–supervisory control and data acquisition) emerge as key differentiators in expediting oil and gas exploration and accelerating operational efficiencies.
Adopting M2M early on enables remote monitoring and allows for more flexible control of assets from wellhead to pipeline. It also enables fiscal metering, drilling monitoring and fleet management, as well as worker safety and accident response.
It means higher productivity and eventually, lower costs for the oil and gas industry.
This is the important part: The number of devices with cellular or satellite connectivity deployed in oil and gas applications worldwide is expected to rise more than 20% over the next several years.
The top two applications for M2M in the oil and gas sector are in-land pipeline monitoring and onshore well-field-equipment monitoring.
The drivers are new regulations, rising operating costs (think unconventional drilling) and increasing competition (a lot more players on the field, and the rising ranks of the juniors).
WHO TO WATCH (AND OWN)
In the high-tech hydrocarbons game these are our four picks: General Electric (GE) for subsea infrastructure; Transocean (RIG) for deep and ultra-deepwater rigs, Schlumberger for 3D seismic, and FMC Technologies.
As upward pressure pushes up day rates for deep-water (especially ultra-deep) rigs, it’s Transocean (NYSE:RIG) all the way. This year’s already been a pretty good year for Transocean, despite some rather serious legal problems, and it’s got a nice backlog of contracts. But we’re also looking at Ensco and SeaDrill.
But hands down, it’s GE Oil & Gas, General Electric’s fastest-growing segment, with annual 16% revenue growth over the last three years. GE is one of the most diverse companies out there, and it has carved itself a nice niche in the oil and gas sector. And it’s impressively forward-thinking—from massive LNG projects to subsea drilling equipment. GE is positioned to experience significant growth.
This year has been an amazing year for GE Oil & Gas, with a list of contracts that would impress the biggest skeptic. Since January, GE has sealed a $620 million, 22-year contract for QGC’s Queensland Curtis LNG plant offshore Australia; a $333 million 16-year contract extension for Russia’s Sakhalin-2 LNG plant; a $500 million contract Petrobras for new pre-salt projects in Brazil; $600 million in multiple-customer propulsion system contracts; and most recently, a $147 million deal with Statoil for carbon dioxide injection. Adding to GE Oil & Gas’ market share here is the recent acquisition of Lufkin Industries. Though it had a very rough time of things during the financial crisis, GE has turned around—and quickly. Downsizing GE’s Capital Division has been fortuitous, and we see huge things ahead for this company.
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